Thermal pulsing procedure for remediation of cold spots in steam assisted gravity drainage

ABSTRACT

A method for remediation of at least one cold spot in a producer well in a Steam Assisted Gravity Drainage (SAGD) process to increase hydrocarbon recovery from a hydrocarbon reservoir, wherein the SAGD process occurs at a site including an injection well, a production well and a steam chamber. The method includes shutting the production well and maintaining or increasing steam injection through the injection well until pressure in the steam chamber increases. The production well is then resumed while continuing steam injection at rates for normal SAGD or greater until reservoir pressure reaches normal operational pressure. Optionally, the injection/production is adjusted to return to normal SAGD operation.

BACKGROUND

Steam Assisted Gravity Drainage (“SAGD”) is currently the dominant in situ enhanced oil recovery (“EOR”) process to recover bitumen from Canadian oil sands. SAGD has two parallel horizontal wells (a producer well and a steam injector well), about 5 metres apart, with the lower producer well completed in the pay zone, close to the bottom of the pattern recovery zone, and a steam injector well above the lower producer well. The pattern recovery zone volume is about 100 metres wide (100 metres spacing) and up to 1000 metres long (1000 metres well length).

SAGD is executed in 3 phases—(i) at least one start-up phase, where steam circulation from the steam injector well and production well is used to establish communication between the parallel horizontal wells; (ii) at least one ramp-up phase where a steam chamber is formed in the pattern recovery zone and grows both laterally and vertically until it hits the pay ceiling; and (iii) a wind-up phase where vertical growth is stopped by the pay ceiling but lateral growth continues and productivity slows down as the slope of the chamber walls decrease.

In the at least one ramp-up phase of SAGD, there are 3 measures of performance, namely the steam-to-oil ratio (“SOR”) (a measure of energy efficiency); bitumen productivity; and water return ratio (how much steam injected is returned as produced water). The dominant economic factors, in descending order, are: bitumen productivity; start-up time before SAGD can be started; SOR; and water return ratio.

Because SAGD is a saturated-steam process wherein temperature and pressure are linked, an operator will always have a strong incentive to operate SAGD at the highest pressure possible, even if the operating pressure is higher than native reservoir pressure (i.e. overpressure operation). The reason is simple. At higher pressure saturated steam temperature is higher and bitumen is heated to a higher temperature, reducing viscosity significantly, allowing for ease of flow of bitumen. Bitumen viscosity is a strong function of temperature. Bitumen productivity is proportional to the inverse square root of viscosity (Butler (1991)), so higher pressure results in higher bitumen productivity—the dominant economic factor. The choice of increasing temperature in SAGD may reduce process efficiency for two reasons. Since bitumen is produced at/near saturated steam temperature, it is predominantly the latent heat of steam that drives the SAGD process. As pressure and temperature are increased, the latent heat content in saturated steam drops, so efficiency is lost. Also, at higher temperature and pressure conditions, the reservoir matrix requires heating to higher temperatures. This increased heat demand also reduces efficiencies.

Bitumen reservoirs may be characterized by their hydraulic behaviour as follows:

-   -   (1) Type A bitumen reservoir—is essentially homogeneous, with no         bottom/top water, no top gas, no lean zones and few shale         baffles. Prior to bitumen production, water injection tests         (Aherne, A. L. et al ‘Fluid Movement in the SAGD Process: A         Review of the Dover Project’, Can. Int'l Pet. Conf., Jun.         13, 2006) show no/little injectivity into the pay zone. A         typical SAGD steam chambers is regular-shaped and pressure         contained. Over-pressurization (i.e. operating SAGD at pressures         greater than native reservoir pressure) is feasible and it is         the normal procedure.     -   (2) Type B bitumen reservoir—exhibits some heterogeneities         (shale baffles, lean zones . . . ) but there is no “active”         water from lean zones, and no “active” water from bottom/top         water. There are “limited” lean zones and/or “limited” water         incursion. SAGD steam injection volumes, at peak, are about 500         m³/d so “significant” water incursion is more than about 50 m³/d         (i.e. “active” water zones). Prior to bitumen production, water         injection tests show some injectivity (i.e. linked to a         “limited” water zone). The degree of impact of water incursion         and/or water recharge rates is also a function of pressure. At         higher SAGD operating pressure compared to native reservoir         pressure, water loss/recharge may become more significant. Over         pressure operation of SAGD may be feasible, but with increasing         fluid losses. The usual remedy to reduce fluid losses is to         reduce SAGD operating pressures to/near native reservoir         pressure.     -   (3) Type C bitumen reservoir—has significant active water zones         from either bottom/top water or lean zones—that may act as thief         zones during SAGD. Prior to production, water injection tests         show significant injectivity (connection to active water zones).         Fluid loss rates or recharge rates are greater than about 50         m³/d. Overpressure SAGD operation is not possible. SAGD must be         operated at/near native reservoir pressure. Even then, operation         may be difficult if natural pressure gradients (i.e. pressure         differentials in the production well or pressure differentials         produces as a result of formation of a gas gravity drainage         chamber) cause influx or egress of significant fluid volumes.

Given the above reservoir categorization by hydraulic behaviour, the type of classification of each reservoir is sensitive to hydraulic factors. For example, at lower SAGD pressure a Type B reservoir may behave like a Type A reservoir. Also, reservoir types above may change as a SAGD project matures, particularly if the growing steam chamber encounters an active water zone or even a limited water zone.

The objective of the SAGD start-up phase is to establish communications between the two horizontal wells and to heat/mobilize the bitumen between the wells, uniformly to a target temperature, usually about 100° C. The start-up phase is accomplished by circulating steam in both the upper (injector) and lower (producer) horizontal wells. The start-up may also be broken into phases. If steam is injected at the well heel, for circulation, the first hurdle is to reach steam temperature at the well toe. To reach steam temperature it may take, at least, a few days (Vanegas (2006)). Then steam injection/circulation is continued for several weeks (or a few months), with both wells at the same pressure. Heat is transferred to the reservoir by conduction. Then, the operator may establish a pressure differential between upper/lower wells, while still circulating steam in each well, with the upper well at the higher pressure. This well pressure differential is modest (−100 Kpa), so preferential flow channels are not created. The objective is to add a convection mechanism to heat transfer to speed up communications (Vanegas P. et al, ‘Impact of Operational Parameters and Reservoir Variables during the Start-up Phase of a SAGD Process’, Pet. J. Online, Nov. 16, 2006, Yuan, J. Y. et al ‘Evaluation of Steam Circulation Strategies for SAGD Start-up’ Can. Intl. Pet. Conf., Calgary, Jun. 16, 2009, and Parmar, G. et al, ‘Start-up of SAGD Wells: History Match, Wellbore Design and Operation’, JCPT, January 2009).

After a few (several) months, SAGD may be started by injecting steam only in the upper well (injector) producing hot fluids in the lower well (hot bitumen+condensed steam). In SAGD, the start-up phase time is longer for reservoirs with heavier, more viscous bitumen. A small steam chamber is formed and the ramp-up SAGD phase starts and matures as the chamber grows upward and outward. Production increases as the chamber grows and peaks when the ceiling of the pay zone is reached.

For a Type A reservoir, operating control for SAGD is simple. The operator chooses a pressure target, which can be higher than native reservoir pressure. Pressure is monitored by down-hole sensors. The steam injection rate is adjusted to attain pressure target. The production rate is controlled (electric submersible pump (“ESP”) or gas lift) to meet a temperature target in the production well, monitored by down-hole thermocouples. The temperature target is set at a sub-cool target compared to saturated steam temperature in the reservoir (usually 10-20° C. sub-cool), to ensure that the production well is producing only liquids (bitumen+water) and not live steam. Sub-cool is the difference between the saturated steam temperature at the producer pressure and the actual temperature at where pressure is measured. This is also called steam-trap control (VanderValk, P. A. et al ‘Investigation of Key Parameters in SAGD Wellbore Design and Operation’, JCPT, June, 2007).

For type B and/or C reservoirs, steam-trap control may be much more difficult. Overpressure operation of SAGD may not be feasible. If cold water or cold spots are in part of the production well (or producer well), steam-trap control may be lost. For homogeneous SAGD operation, if production is increased, temperature in the production well will also increase as hotter production fluids or some steam are drawn to the production well. This directionality is used as the basis of steam-trap control. If there is a cold zone in the production well formed as the result of reservoir water incursion, and if production rate is increased, temperature in the production well may drop if more cold water is drawn in.

In an ideal world, during SAGD at the end of the start-up phase and in the early ramp-up phase, there would be a homogeneous distribution of heat in the reservoir and a flat temperature profile in the production well. Each segment of the reservoir would contribute equally to bitumen production. Steam chamber shape would be smooth and regular. Unfortunately, homogeneous production for SAGD is rare, even for Type A reservoirs, for the following reasons:

-   -   (1) Steam circulation during start-up is not homogeneous         throughout the well. Most heat is delivered to the well heel.     -   (2) Bitumen reservoirs may have gross inhomogeneities—top/bottom         water, top gas, shale baffles, shale barriers, lean zones . . .         etc.     -   (3) Bitumen reservoirs may also have subtle         inhomogeneities—lateral and vertical permeability variations,         porosity variations, matrix composition—that may influence         conformance.     -   (4) A pressure gradient (between the parallel horizontal wells)         used during the start-up phase may create high-permeability         channels that transport steam, bitumen, water and heat between         the parallel horizontal wells.     -   (5) Bitumen properties are not homogeneous within a reservoir.         Vertical and lateral variation of bitumen quality may be         significant and variations may easily influence start-up and         ramp-up conformance (Larter, S. ‘Viscous Variations and         Asphaltic Aspirations’, Gushor Inc. Newsletter, October 2010).     -   (6) Lean zones, where bitumen saturation is low, water         saturation is high and water has some mobility, are a particular         concern (Vanderklippe, N. ‘Long Lake Project hits Sticky Patch’,         Globe & Mail, Feb. 10, 2011, Reuters, ‘Update 3—Long Lake Oil         Sands, Output may lag Targets’, Feb. 10, 2011). Many operators         are concerned about lean zone effects (Oilsands Quest, ‘Axe         Lake, SAGD Test Horizontal Well Pair Configuration: Project         Summary Document’, Jul. 14, 2010, Peterson, J. A. et al,         ‘conducting SAGD in Shoreface Oil Sands with Associated Basal         Water’, Laricina Energy, 2009, Oilsands Quest, ‘Management         Presentation’, January 2011, Akram, F. ‘Reservoir Simulation         Optimizes SAGD’, O&G Reporter, September 2010, and         Johnson, M. D. et al, ‘Production Optimization at Connacher's         Pod One (Great Divide) Oil Sands Project’, SPE Conf., Jul. 19,         2011).

If start-up or ramp-up phases have created or established non-homogeneous heat distribution, a manifest measurement of the condition is “cold spots” in the production well. If cold spots are formed, they can be surprisingly resilient (Larter (2010)). In the ramp-up (or wind-up) phase of SAGD the operator has limited tools to remediate the “cold spots” (VanderValk (2007)). Sub-cool may be varied, injection tubing size may be varied (or insulated), or pressure targets may be altered. These remedies are not very successful.

There is need for a method to remediate cold spots in the production well, and in particular a production well undergoing SAGD.

SUMMARY OF THE INVENTION

SAGD is now the dominant in-situ EOR process to recover bitumen from Canadian oil sands. SAGD comprises two parallel horizontal wells, about five metres apart, completed near the bottom of a bitumen reservoir. The upper well continuously injects steam and the lower well produces heated bitumen and condensed steam (water). For a healthy process, all parts of the producer well should be hot and contribute to production. If cold spots form in this well it is an indication of reduced productivity and poor conformance.

According to one aspect of the invention, there is provided a procedure to heat up at least one cold spot, preferably a plurality of cold spots, in a producer (or production) well of a SAGD process, to increase production and improve conformance by introducing a “thermal pulse procedure” to the SAGD process. The thermal pulse procedure (TPP) comprises shutting in the producer well, increasing or maintaining steam injection rates from a steam injector well, opening up the producer well and reinstating normal SAGD operation.

According to another aspect of the invention there is provided a method for remediation of at least one cold spot in a SAGD process, said SAGD process comprising a steam injector well, a production well, a steam chamber, and at least one cold spot, preferably a plurality of cold spots, proximate said production well, the remediation method comprising:

-   -   (1) shutting the production well;     -   (2) maintaining or increasing steam injection through the steam         injector well until pressure in the steam chamber increases,         preferably less than or equal to a 0.3 MPa increase, more         preferably up to a 0.5 MPa increase;     -   (3) resuming the production well while continuing steam         injection through the steam injector well at rates for normal         SAGD or greater, until reservoir pressure reaches normal         operational pressure; and optionally     -   (4) adjusting injection/production to return to normal SAGD         operation;

This remediation method increases hydrocarbon recovery from a hydrocarbon deposit. Typically when adjusting steam injection, the following parameters are adjusted: steam injection rate to reach and/or maintain a preferred pressure target. Typically, when adjusting the producer well, fluid withdrawal rate from the producer well is adjusted to reach and/or maintain a preferred sub cool target.

According to yet another aspect of the invention, there is provided an improvement in Steam Assisted Gravity Drainage (“SAGD”) for increasing hydrocarbon recovery from a bitumen reservoir, wherein said SAGD comprises at least one steam injector well, at least one producer well with at least one cold spot, and at least one steam chamber, said improvement comprising:

-   -   (1) shutting the at least one producer well;     -   (2) maintaining or increasing steam injection through the at         least one steam injector well until pressure in the at least one         steam chamber increases, preferably less than or equal to a 0.3         MPa increase, more preferably up to a 0.5 MPa increase;     -   (3) resuming the at least one producer well while continuing         steam injection through the at least one steam injector well at         rates for normal SAGD or greater, until bitumen reservoir         pressure reaches normal operational pressure; and optionally     -   (4) adjusting injection/production to return to normal SAGD         operation

In a preferred embodiment, the at least one cold spot has a temperature of about 10° C. to about 20° C. lower than SAGD sub-cool targets, more preferably at least 20° C. lower than SAGD sub-cool targets. Preferably said sub-cool target in SAGD is in the range of from about 0° C. to about 25° C., more preferably from about 5° C. to about 20° C. In yet another preferred embodiment, the cold spots are formed by cold water incursion from the reservoir water zone, preferably the water recharge rates from the reservoir water zone are less than about 500 m³/d, more preferably less than about 50 m³/d.

Preferably, said bitumen reservoir is selected from the group consisting of a homogenous Type A reservoir, heterogeneous Type B reservoir, Type C reservoir and mixtures thereof

Preferably said at least one cold spot is monitored at some point, preferably throughout said process.

More preferably, said remediation process is carried out during the ramp-up phase of SAGD.

BRIEF DESCRIPTION OF THE FIGURES

FIG. 1 depicts a typical SAGD Well Configuration known in the art.

FIG. 2 depicts a typical ramp-up phase in a SAGD process.

FIG. 3 depicts a typical wind-up phase in a SAGD process.

FIG. 4 depicts Saturated steam properties.

FIG. 5 depicts steam injection rates, electrical submersible pump rates of bitumen and water, and well heel temperatures when incorporating one embodiment of the present invention.

FIG. 6 depicts well heel temperature response when incorporating an embodiment of the present invention.

FIG. 7 depicts the Steam to Oil Ratio (SOR) and Oil rates when incorporating an embodiment of the present invention.

FIG. 8 depicts the Oil rates when incorporating an embodiment of the present invention.

FIG. 9 depicts well pair performance over a period of 4 years when incorporating an embodiment of the present invention.

FIG. 10 depicts a proposed well pair configuration and monitoring layout according to one embodiment of the invention

DETAILED DESCRIPTION OF THE INVENTION

According to FIG. 1, as discussed above, Steam Assisted Gravity Drainage (“SAGD”) is currently the dominant in situ enhanced oil recovery (“EOR”) process to recover bitumen from Canadian oil sands. SAGD has two parallel horizontal wells (a producer well (10) and a steam injector well (20)), about 5 metres apart, with the lower producer well (10) completed in the pay zone (30), close to the bottom of the pattern recovery zone (40), and a steam injector well (20) above the lower producer well (10). The pattern recovery zone (40) volume is about 100 metres wide (100 metres spacing) (50) and up to 1000 metres long (1000 metres well length).

SAGD is executed in 3 phases—(i) a start-up phase, where steam circulation from the steam injector well is used to establish communication between the parallel horizontal wells; (ii) a ramp-up phase (as best seen in FIG. 2) where a steam chamber (60) is formed in the pattern recovery zone (70)) and grows both laterally (61) and vertically (62) until it hits the pay ceiling (80); and (iii) a wind-up phase (as best seen in FIG. 3) where vertical growth is stopped by the pay ceiling (80) but lateral growth continues and productivity slows down as the slope of the chamber walls (61) decrease.

As discussed above, the choice of increasing temperature in SAGD may reduce process efficiency for two reasons. Since bitumen is produced at/near saturated steam temperature, it is predominantly the latent heat of steam that drives the SAGD process. As pressure and temperature are increased, the latent heat content in saturated steam drops (as best seen in FIG. 4), so efficiency is lost. Also, at higher temperature and pressure conditions, the reservoir matrix requires heating to higher temperatures. This increased heat demand also reduces efficiencies.

The “thermal pulse” remediation process (TPP) of the present invention may be applied to a SAGD process with at least one cold spot in a production well, as follows:

-   -   (1) shut-in the production well;     -   (2) increase or maintain steam injection rates;     -   (3) when pressure increases up to about 0.5 MPa (a few days or a         week), produce the production well at/near maximum rates (gas         lift or ESP) for a few days, up to about 1 week; and     -   (4) Restart normal SAGD operations optionally monitoring the at         least one cold spot temperature.

Although not wanting to be limited by the following, it is believed the invention is effective due to as follows:

-   -   a. during the shut-in/steam injection phases ((1) and (2)         above), steam will displace water in the zone proximate the at         least one cold spot;     -   b. hot production fluids (hot bitumen+condensed steam) builds up         at/near the bottom of the steam chamber;     -   c. during the production phase (3) above), steam is removed         quickly from the water zone creating a cold spot and before         recharging by cold water can occur, hot production fluids (hot         bitumen+condensed steam) will be drawn into the zone with the         cold spot; and     -   d. the hot production fluids inhibit recharging by cold water.

The present invention relies firstly on a slow/limited recharge rate of cold water and a fast saturation with hot production fluids. Secondly, the remediation based on the present invention may be temporary or permanent depending on the reservoir type and operating strategy following remediation. Thirdly, if the water recharge rate is rapid (i.e. Type C reservoir) the present invention may not produce ideal results. Fourth, the present invention relies on ability to increase reservoir pressure. Again, this condition may not produce ideal results for a Type C reservoir.

EXAMPLE 1

-   -   (1) A field test of the thermal pulse process (TPP) according to         the present invention in a SAGD well pair near Long Lake,         Alberta was conducted over a period of two days. The pressure         pulse for the test was about 260 kPa during the two day test.         Prior to the test, the steam injector pressure was about 2000         kPa (saturated steam temperature=213° C.).

FIGS. 5-8 show process measurements over the two day testing period.

As best seen in FIG. 5, prior to incorporating the remediation process in an existing SAGD well pair, the thermocouples in the heel of the producer well registered temperatures from about 140° C. to 160° C. Given the temperature of saturated steam is about 213° C., the temperature fluctuation of from about 140° C. to 160° C. indicates a cold spot is present in the heel of the producer well, given the heel zone is expected to be hot given the heel zone is the first zone to receive steam and collects all the production fluids. It is also observed that subsequent to the remediation process, the heel temperature rose quickly to between 180° C. and 190° C. and this increased temperature was maintained for a period of time. As best seen in FIGS. 6, 7, 8 and 9, the oil recovery rate increased concurrently with remediation of the cold spot. Referring now to FIGS. 7 and 9, the SOR varies considerably. FIG. 9 shows the total history of the well pair prior to, during, and post testing. SAGD was initiated in January 2008. The SAGD pair was in the ramp-up phase of SAGD. As best seen in FIG. 10, the instrumentation in the well pair (10, 20) is shown, including 6 thermocouples (90) in the production well, pressure measurement at the producer heel (100) and toe (110) and at the injector heel (120) subsequent to implementation of the present invention.

It is clear from the above that the current invention increases productivity in SAGD processes when a producer well has at least one cold spot.

Preferably, when incorporating the present invention in a type B reservoir, it is preferred that there are limited leaks and there is some ability to increase pressure; when incorporating the present invention during the ramp-up phase of SAGD, it is preferred to remediate the cold spot(s) as early as possible; it is preferred to limit repressurization to no more than about +0.5MPa; and the cold spot in the production well is preferably greater than about 10° C. below sub cool target temperature.

As many changes can be made to the preferred embodiment of the invention without departing from the scope thereof; it is intended that all matter contained herein be considered illustrative of the invention and not in a limiting sense. 

1. A method for remediation of at least one cold spot in a producer well in a Steam Assisted Gravity Drainage (SAGD) process, to increase hydrocarbon recovery from a hydrocarbon reservoir, said SAGD process occurring at a site comprising an injection well, a production well, and a steam chamber, wherein said method comprises: (a) shutting the production well; (b) maintaining or increasing steam injection through the injection well until pressure in the steam chamber increases; (c) resuming the production well while continuing steam injection at rates for normal SAGD or greater, until reservoir pressure reaches normal operational pressure; and optionally (d) adjusting injection/production to return to normal SAGD operation.
 2. The method of claim 1 wherein the pressure in the steam chamber increases up to about 0.5 MPa.
 3. The method of claim 1 wherein the at least one cold spot has a temperature of about 10° C. to 20° C. lower than a SAGD sub cool target temperature.
 4. The method of claim 1 wherein the at least one cold spot is formed by cold water incursion from a water zone in said reservoir.
 5. The method of claim 4 wherein the cold water incursion has a water recharge rate from the water zone of less that about 500 m³/d.
 6. The method of claim 1 wherein the reservoir is a heterogeneous Type B reservoir.
 7. The method of claim 1 wherein the reservoir is a homogeneous Type A reservoir.
 8. The method of claim 1 wherein the reservoir is a homogeneous Type C reservoir.
 9. The method of claim 4 wherein the cold water incursion has a water recharge rate from the water zone of less than about 50 m³/d.
 10. The method of claim 1 wherein the pressure in the steam chamber pressure increases up to less than or equal to about 0.3 MPa.
 11. The method of claim 3 wherein the at least one cold spot is at least about 20° C. lower than SAGD sub cool target temperature.
 12. The method of claim 2 wherein the at least one cold spot is formed by cold water incursion from a water zone in said reservoir.
 13. The method of claim 3 wherein the at least one cold spot is formed by cold water incursion from a water zone in said reservoir. 